In oil and gas exploration it is desirable to understand the structure and properties of the geological formation surrounding a borehole, in order to determine if the formation contains hydrocarbon resources (oil and/or gas), to estimate the amount and producibility of hydrocarbon contained in the formation, and to evaluate the best options for completing the well in production. As discussed below, distinguishing NMR signals due to water in the muds and formation from the NMR signals from native hydrocarbons is known. However, for many reasons, such as for better mechanics of drilling, i.e., well-bore stability, suppression of swelling clays, etc., it is desirable to use oil-based muds instead of water-based muds. This naturally makes the interpretation of NMR signals challenging in the course of evaluating a formation.
The hydrocarbon identification methods used most often with NMR logs, e.g., Time Domain Analysis (TDA), Enhanced Diffusion Method (EDM) etc., rely upon extracting a signal(s) from NMR measurements that is directly related to the amount of hydrocarbon entities present in the tools' sensitive volume. These prior art methods work well in situations where the reservoir is drilled with a water-based mud because the native hydrocarbons have individual NMR properties distinguishable form the properties of the mud. However, when oil-based muds are used, some miscibility is bound to occur between invading oil-based mud filtrate and native hydrocarbons. The miscible solution of oil-based mud filtrate and native hydrocarbon(s) will have NMR relaxation and diffusivity properties which are a combination of NMR fluid properties of the individual hydrocarbon components. Thus, errors can arise when the prior art quantitative methods are applied in situations where oil-based muds are used because the NMR properties of the individual components are not readily distinguishable.
In recent years NMR logging has become very important for purposes of formation evaluation and is one of the preferred methods for determining formation parameters. Improvements in the NMR logging tools, as well as advances in data analysis and interpretation allow log analysts to generate detailed reservoir description reports, including clay-bound and capillary-bound related porosity, estimates of the amounts of bound and free fluids, fluid types (i.e., oil, gas and water), permeability and other properties of interest.
The importance of Nuclear magnetic resonance (NMR) logging, at least in part, is due to the fact that unlike nuclear porosity logs, the NMR measurement is environmentally safe and is unaffected by variations in matrix mineralogy. The NMR logging method is based on the observation that when an assembly of magnetic moments, such as those of hydrogen nuclei, are exposed to a static magnetic field they tend to align along the direction of the magnetic field, resulting in bulk magnetization. The rate at which equilibrium is established in such bulk magnetization upon provision of a static magnetic field is characterized by the parameter T1, known as the spin-laftice relaxation time.
Another related and frequently used NMR logging parameter is the so called spin-spin relaxation time constant T2 (also known as transverse relaxation time) which is an expression of the relaxation due to non-homogeneities in the local magnetic field over the sensing volume of the logging tool.
NMR tools used in practical applications include, for example, the centralized MRIL® tool made by NUMAR Corporation, a Halliburton company, and the sidewall CMR tool made by Schlumberger. The MRIL® tool is described, for example, in U.S. Pat. No. 4,710,713 to Taicher et al. and in various other publications including: “Spin Echo Magnetic Resonance Logging: Porosity and Free Fluid Index Determination,” by Miller, Paltiel, Gillen, Granot and Bouton, SPE 20561, 65th Annual Technical Conference of the SPE, New Orleans, La., Sep. 23–26, 1990; “Improved Log Quality With a Dual-Frequency Pulsed NMR Tool,” by Chandler, Drack, Miller and Prammer, SPE 28365, 69th Annual Technical Conference of the SPE, New Orleans, La., Sep. 25–28,1994. Certain details of the structure and the use of the MRIL® tool, as well as the interpretation of various measurement parameters are also discussed in U.S. Pat. Nos. 4,717,876; 4,717,877; 4,717,878; 5,212,447; 5,280,243; 5,309,098; 5,412,320; 5,517,115, 5,557,200; 5,696,448 and 5,936,405. The structure and operation of the Schlumberger CMR tool is described, for example, in U.S. Pat. Nos. 4,939,648; 5,055,787 and 5,055,788 and further in “Novel NMR Apparatus for Investigating an External Sample,” by Kleinberg, Sezigner and Griffin, J. Magn. Reson. 97, 466–485, 1992; and “An Improved NMR Tool Design for Faster Logging,” D. McKeon et al., SPWLA 40th Annual Logging Symposium, May–June 1999. The content of the above patents is hereby expressly incorporated by reference for all purposes, and all non-patent references are incorporated by reference for background.
U.S. Pat. No. 6,051,973, assigned to the assignee of this application, which is incorporated herein in its entirety for all purposes, discloses a method and system for measuring a saturation-recovery sequence to reduce errors due to the motion of the logging tool. Motion-independence is achieved, for instance, by issuing a broadband saturation pulse that covers a large volume within the sample, followed by a narrow-band read-out sequence such that the narrow-band is within the broadband saturation pulse.
The MRIL® tool is capable of performing a variety of borehole NMR logging measurements. See, for example, the U.S. Pat. No. 6,242,912 B1, assigned to the assignee of the present application, which teaches systems and methods for lithology independent gas detection. U.S. Pat. No. 6,005,389 assigned to the assignee of the present application teaches the use of a rapid-fire CPMG pulse sequence to detect and quantify components having very short relaxation times, such as clay-bound water. The entire content of these patents is incorporated herein by reference.
NMR tools of the type discussed above generally measure the time for hydrogen nuclei present in the earth formation to realign their spin axes, and consequently their bulk magnetization, either with an externally applied magnetic field, or perpendicularly to the magnetic field, after momentary reorientation due to the application of specific radio frequency (RF) pulses. The externally applied magnetic field is typically provided by a magnet disposed in the tool. The spin axes of the hydrogen nuclei in the earth formation are, in the aggregate, caused to be aligned with the externally applied magnetic field. The NMR tool includes an antenna such that a pulse of radio frequency (RF) power conducted through the antenna induces a magnetic field in the earth formation orthogonal to the externally applied magnetic field. The RF pulse has a duration predetermined to generally align the spin axes of the hydrogen nuclei perpendicular both to the orthogonal magnetic field induced by the RF pulse and to the externally applied magnetic field. After the pulse ends, the nuclear magnetic moment of the hydrogen nuclei gradually relaxes, i.e., returns to their alignment with the externally applied magnetic field; at the same time an antenna, electrically connected to a receiver, helps detect and measure voltages induced in the antenna by precessional rotation of the spin axes of the hydrogen nuclei.
An actual NMR measurement involves a plurality of pulses grouped into pulse sequences, most frequently of the type known in the art as Carr-Purcell-Meiboom-Gill (CMPG) pulsed spin echo sequences. As known in the art, each CPMG sequence consists of a 90-degree (i.e., π/2) pulse followed by a large number of 180-degree (i.e., π) pulses. The 90-degree pulse rotates the proton spins into the transverse plane and the 180-degree pulses generate a sequence of spin echoes by refocusing the transverse magnetization after each spin echo.
Another concern in NMR data is the signal-to-noise ratio, which may be improved by experiment stacking. In the multi-frequency MRIL® Prime tool the use of multiple NMR measurement frequencies is conceptually equivalent to the simultaneous acquisition of multiple passes with the earlier logging tools. Thus, MRIL® Prime logs could be acquired at faster logging speeds, with the required SNR obtained by stacking multiple signals across the frequency bands. However. in formations with high-signal levels, this approach may result in more stacking being selected than is necessary to provide adequate signal-to-noise ratio.
An important measurement parameter used in NMR well logging is the diffusion constant D. Generally, diffusion refers to the motion of atoms in a gaseous or liquid state due to their thermal energy. The diffusion D constant is dependent on the pore sizes of the formation and offers much promise as a separate permeability indicator. In a uniform magnetic field, diffusion has little effect on the decay rate of the measured NMR echoes. In a gradient magnetic field, however, diffusion causes atoms to move from their original positions to new ones, which moves also cause these atoms to acquire a different phase shifts compared to atoms that did not move, and thus results in an apparently faster rate of relaxation. Therefore, in a gradient magnetic field diffusion is a logging parameter, which can provide independent information about the structure of the geologic formation of interest, the properties of the fluids in it, and their interaction.
In the paper, entitled “NMR Logging of Natural Gas Reservoirs,” presented at the 36th Annual SPWLA Symposium, Paris, Jun. 26–29,1995, Akkurt, R. et al. have shown one approach of using the capabilities provided by HALLIBURTON's MRIL® tool for detection of gas. The content of the Akkurt et al. paper is incorporated herein by reference. In this paper, the authors point out that NMR signals from gas protons are detectable, and derive T1 relaxation and diffusion properties of methane-dominated natural gas mixtures at typical reservoir conditions. The magnetic field gradient of the MRIL® is used to separate and to quantify water, oil and gas saturations based solely on NMR data.
The results in the Akkurt paper are based on the HALLIBURTON's MRIL-CE® tool, the output of which is used to obtain T2 spectra. T2 spectra are extracted from the raw CPMG echo trains by breaking the total NMR signal M(t) into N components, called bins, according to the formula:
      M    ⁡          (      t      )        =            ∑              i        =        1            N        ⁢                  a        i            ⁢              exp        ⁡                  (                                    -              t                        /                          T              2                                )                    where ai is the porosity associated with the i-th bin. Each bin is characterized by a fixed center transverse relaxation time T2i. The total NMR porosity is then determined as the sum of the porosities ai in all bins. The T2 spectrum model is discussed in detail, for example, in Prammer, M. G., “NMR Pore Size Distributions and Permeability at the Well Site,” paper SPE 28368, presented at the 69-th Annual Technical Conference and Exhibition, Society of Petroleum Engineers, New Orleans, Sep. 25–28, 1994, the content of which is incorporated herein for all purposes.
On the basis of the T2 spectra, two methods for detecting gas deposits are proposed in the Akkurt paper and will be considered briefly next to provide relevant background information. The first method is entitled “differential spectrum method” (DSM), which is based on the observation that often light oil and natural gas exhibit distinctly separated T2 measurements in the presence of a magnetic field gradient, even though they may have overlapping T1 measurement values. The DSM makes use of these observations and is illustrated by a specific example for a sandstone reservoir containing brine, light oil and gas. According to the Akkurt et al. paper, two separate logging passes are made with different wait times TR1, and TRs, such that the longer time TR1≧T1g, and the shorter time satisfies the relationship T1g≧TRs≧3T1wmax.
Due to the large T1 contrast between the brine and the hydrocarbons the water signal disappears when the spectra of the two signals are subtracted. Thus, the differential T2 spectrum contains only hydrocarbon signals. It should be noted that the subtraction of the T2 spectra also eliminates all bound water, making the DSM very useful in shaly sands.
The second method proposed in the Akkurt et al. paper is called “shifted spectrum method” (SSM). Conceptually the method is based on the observation that since the surface relaxation for gas is negligible, the apparent T2 relaxation can be expressed as:
      1          T      2        =            1              T                  2          ⁢          B                      ⁡          [              1        +                                                            (                                  γ                  ⁢                                                                          ⁢                  G                  ⁢                                                                          ⁢                  τ                                )                            2                        ⁢                          DT                              2                ⁢                B                                              2                    ]      where G is the magnetic field gradient, D is the diffusion coefficient, τ is half the interecho time, γ is the gyromagnetic ratio and T2Brefers to the bulk relaxation. It is known in the art that for gas, which is a non-wetting phase, T1=T1B≈T2B. Therefore, given that the product D0*T1 of a gas after substitution in the expression above is an order of magnitude larger than oil and two orders of magnitude larger than brine, it can be seen that the already large DT1 contrast of gas can be enhanced even further by increasing the inter-echo time, 2τ, in order to allow the separation of two fluids that overlap in T1. The SSM is based on the above concept and may result in the signal from gas being shifted out of the detectability range, so that the single spectrum peak is due to brine.
Prior art methods used most often with NMR logs, e.g., Time Domain Analysis (TDA), Enhanced Diffusion Method (EDM), etc. rely on extracting signals from NMR measurements that are directly related to the amount of hydrocarbon present in the tool's sensitive volume. These methods work satisfactorily with Water-Based Muds (WBM) since native hydrocarbons retain their distinct properties. However, with the use of Oil-Based Mud (OBM) and Oil-Based Mud Filtrates (OBMF) in drilling, the NMR signals are due to a combination of native hydrocarbon species and OBMF leakage due to the increased likelihood of miscibility with native hydrocarbons.
It is known that diffusion constants of different components of interest behave differently as a function of T2 relaxation times. Oil and hydrocarbons are generally classified on the basis of viscosity, with the low viscosity oils exhibiting a higher diffusion constant than the high viscosity heavier oils. The diffusion constant of oil also tends to be linearly proportional to the T2 relaxation time. For gases and bulk water the diffusion constant is substantially independent of the T2 relaxation time while being dependent on the temperature. In addition, for gases, the diffusion constant is a function of the pressure.